HISTORY OF PIPING SIZE TERMS Pipe sizes can be confusing because the terminology may relate to historical dimensions. For example, a half-inch iron pipe does not have any dimension that is a half inch. Initially, a half inch pipe did have an inner diameter of 0.5 inches (13 mm)—but it also had thick walls. As technology improved, thinner walls became possible, but the outside diameter stayed the same so it could mate with existing older pipe, increasing the inner diameter beyond half an inch. The history of copper pipe is similar. In the 1930s, the pipe was designated by its internal diameter and a 1⁄16-inch (1.6 mm) wall thickness. Consequently, a 1-inch (25 mm) copper pipe had a 1 1⁄8-inch (28.58 mm) outside diameter. The outside diameter was the important dimension for mating with fittings. The wall thickness on modern copper is usually thinner than 1⁄16 inches (1.6 mm), so the internal diameter is only "nominal" rather than a controlling dimension.[6] Newer pipe technologies sometimes adopted a sizing system as its own. PVC pipe uses the Nominal Pipe Size. Pipe sizes are specified by a number of national and international standards, including API 5L, ANSI/ASME B36.10M and B36.19M in the US, BS 1600 and BS EN 10255 in the United Kingdom and Europe. There are two common methods for designating pipe outside diameter (OD). The North American method is called NPS ("Nominal Pipe Size") and is based on inches (also frequently referred to as NB ("Nominal Bore")). The European version is called DN ("Diametre Nominal" / "Nominal Diameter") and is based on millimetres. Designating the outside diameter allows pipes of the same size to be fit together no matter what the wall thickness.
Ref link http://www.wermac.org/pipes/pipe_part2.html
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What are metering system? Metering systems are used on pipelines to check the values of the gas/NGL parameters (Flow rate, Compositional Analysis& Heating value) when they are subject to change or when Gas/NGL is transferring from one company to another for sales purpose. Pipeline gas metering stations are designed for simultaneous, continuous analysis of the quality and quantity of natural gas being transferred in a pipeline, as follows:
The system consists of a multi-path ultrasonic flowmeter, process gas chromatograph and computer workstation installed, pre-wired and pre-piped in a special air-conditioned shelter with all auxiliary equipment and utilities. Each gas metering station branches off of the pipeline and is used to reduce pressure and meter the gas to the various users. For the pressure reduction and metering stations, the main equipment includes filters, heaters, pressure reducers and regulators, and flow metering skids. In addition, each station is generally equipped with drains for collection and disposal, instrument gas system and storage tanks. Filter Separators Natural gas filter units are installed at each station to remove any entrained liquids and solids from the gas stream. The filters may comprise cyclonic elements to centrifuge particles and liquids to the sides of the enclosing pressure vessel. These particles and liquids will then drop down for collection in a sump, which can be drained periodically. A station inlet filter-separator should be installed upstream of the meter. The filter separator is normally a horizontal unit with a full-size, quick-opening closure and access platform for element change out. The vessel should be equipped with level gauges, high liquid level switches and a differential pressure transmitter across the filter elements. The filter-separator sumps should have automatic drain valves. A condensate tank is installed for atmospheric storage of any liquids removed by the filter separator. Most tanks installed for this purpose are double-walled and installed on a concrete pad. The tank should contain a level gauge and a high liquid level switch. A control valve should be installed downstream of the meter run to control both the flow through the meter and the delivery pressure. This valve will primarily operate to limit the station throughput in order to prevent the incoming gas volume from exceeding the meter capacity or the nominated volume but will also be equipped with a pressure override. The control valve is generally controlled by a gas flow computer (GFC) based upon set points provided by the gas control center. The control valve will normally operate in the fully open position to minimize pressure losses through the station and should have a positioner, position indicator and position transmitter. The GFC would also monitor and control the facilities as well as perform custody transfer quality measurement. The GFC communicates all data to a central control console via the SCADA system. At custody transfers, a gas chromatograph is generally used to determine the gas composition for purposes of calculating the gas gross heating value. This data is provided to the GFC for use in calculating the total gas heating value in the metered gas. A gas sample is taken from a continuously flowing location on the meter and regulator skid. The gas sample is secured at low pressure to minimize lag time utilizing a self-regulating sample probe and routed to the gas chromatograph and moisture analyzer. The moisture analyzer is provided to measure the water content of the gas. Depending on sulphur content of the gas, a sulphur analyzer may be required. http://en.wikipedia.org/wiki/Custody_transfer Meter Skid Piping The piping configuration on the meter skid should allow for bi-directional gas flow through the station by an appropriate piping and valving manifold. However, the gas flow through the meter and regulator should be in one direction only. The control valve is installed between isolation ball valves to allow maintenance. It is prudent to install a manual bypass valve to allow continued operation during control valve maintenance activities. Automatic Shutdown Valve An automatic shutdown valve is normally installed at the pipeline connection. This valve should be remotely operated from the main operating system and equipped with local pneumatic controls, a hydraulic manual override and open/close limit switches. Blowdown of the meter station piping is accomplished by a vent stack located on the station inlet piping and vents on the meter skid located downstream of the meter and downstream of the flow control valve. Vent stacks may or may not include silencers, depending on the noise levels at the closest noise sensitive area (NSA). Heaters Natural gas heaters are installed to avoid the formation of hydrates, liquid hydrocarbons, and water as a result of pressure reduction. The gas heater is designed to raise the temperature of the gas so that after pressure reduction, the temperature of the gas will be above the dew point temperature at operating conditions and maximum flow. The heater is a water bath natural circulation type maintained at a temperature between 158-176 degrees F. Where gas cost is high, an alternative is to use high-efficiency or condensing furnaces for the purpose of preheating the gas rather than the water bath heater. Pressure Reduction And Regulation The pressure-reduction system controls the supply pressure to the gas users at a regulated value. Each system consists of at least two trains of pressure reduction - one operating and the other standby. Each train will normally comprise two regulator valves in series. Regulator valves should be sized for the maximum anticipated volumes at the minimum anticipated inlet pressure during those times of maximum volume. For stations serving multiple residential customers or other non-interruptible services, sufficient regulator capacity needs to be provided so the failure of one regulator valve run will not reduce the facility capacity below required demand. Regulator valves in custody transfer stations are typically of the type that fail in the open position. Sound Pressure Sound pressure levels at all service conditions should be considered. High noise levels (generally defined at greater than 110 dbA) can result in damage to regulators, control valves, control valve accessories, instrumentation and downstream piping. Following are standard measures that can be taken to reduce sound pressure levels or to reduce the effects in the path:
Overpressure Protection Stations do not require an overpressure relief device if a monitor regulator is installed in series in each regulator run or if a monitor regulator is installed in series with and common to all regulator runs. Station relief device capacity should be the largest relief capacity requirement determined from the following criteria using the flow and pressures:
Minimum relief device capacity for the failed regulator(s) should be the maximum total flow at the differential pressure between the inlet and outlet of the regulator(s), in the case where inlet pressure is the upstream line MAOP or maximum source pressure, whichever is less, and the outlet pressure is the downstream MAOP plus allowed overpressure. Metering System The flow rate of the gas has to be measured at a number of locations for the purpose of monitoring the performance of the pipeline system and more particularly at places where custody transfer takes place. Depending on the purpose for metering, whether for performance monitoring or for sales, the measuring techniques used may vary according to the accuracy demanded. Potential for future expansion should be considered when sizing the meter skid length. Typically, a custody transfer metering station will comprise one or two runs of pipe with a calibrated metering orifice in each run. Should an ultrasonic meter be required, it should be designed to meet or exceed the requirements established for ultrasonic meters in AGA-9. Typically, the ultrasonic meter will be a multi-path meter and the meter tubes will be equipped with a flow conditioner. The fully assembled meter tubes should be calibrated at line pressure and full-flow conditions prior to use. Normally, the ultrasonic meter tubes will be designed for a minimum 10D upstream length from the flow conditioner to the meter and 5D lengths downstream of the meter. Further, the meter tube should be honed. Pulsation The elimination of pulsation through the use of pulsation control devices is an important step to take. Pulsation has a tendency to introduce meter errors. Computer analogs are used in the design of pulsation-control equipment. There are several methods of determining if levels of pulsation will cause meter errors, but assessment of square-root error remains the best rule of thumb in determining if pulsation-control equipment is needed to improve absolute accuracy. The square-root error is very predictable and is always positive. This error will always indicate a flow that is greater than the actual flow. Instability errors (which are pulsations that change the orifice coefficient) can vary in magnitude and can also be either positive or negative. A system with severe pulsation only needs a slight change in frequency (as little as a few Hz) to result in an error of several percent. Cathodic Protection It is typical to separate the cathodic protection systems of the pipeline and meter station. This is normally done by installing insulation kits at the flange connections at the meter skid. Buried piping within the meter station, either upstream or downstream of the meter skid, should be cathodically protected from the associated pipeline’s cathodic protection system. Buildings When conditions or regulations require a building to be utilized, typically a pre-engineered type building designed in accordance with the International Building Code is used and is mounted on the meter skid to enclose the ultrasonic meter and flow control valve area only. Normally, the building will not be heated or insulated. Buildings are sized to allow use of a meter-sensor removal tool. The EFM and GC buildings are normally two separate buildings mounted on a common skid. As opposed to the meter building, the EFM building should be climate controlled (heated and air conditioned) and sized for the flow-control equipment and associated uninterrupted power supply (UPS). The GC building is not required to be climate controlled, but should have a hazardous gas detector with warning strobe light. BRIEF HISTORY OF FLANGE Today API Spec 6A and MSS SP-44 specify all flanges commonly used in surface drilling and production. These flanges have a long history and many flanges used in the past have been discontinued, or obsoleted and replaced by more modern configurations. Originally, all flanges related to pipe and became standard as weld neck, threaded and blind configurations. As equipment with integral flanges came to the oilfield, standardization became necessary for functional interchangeability. In the late 1930’s, the American Petroleum Institute (API) adopted the then ASA B16.5 flanges. For 720 psi and 960 psi applications API specified no changes to the ASA B16.5 Standard, using the 300 lb. and 400 lb. flanges respectively. For 2000, 3000, and 5000 psi applications, API specified an increase in material yield strength to the respective ASA B16.5 flanges: 600, 900, and 1500 lb. API signify differences with ASA terms of "lb." to the API term "SERIES", (e.g. ASA 4" 900 lb. flange, 2160 psi working pressure, compared to API 4" SERIES 900 flanges, 3000 psi working pressure), dimensionally the same but differing in name, material strength, and working pressure. API issued the first specification for wellhead flanges as 6B, later incorporated into API 6A. The original flanges specified, retained the designation "6B". All API flanges adopted for wellhead use have Ring Type Joint (RTJ) facing. API flanges may have Full Face or Raised Face geometry, with either case having the specified ring groove. Most wellhead manufacturers make their 6B flanges full face. Note: The ASA (now ANSI) terms 300 lb. through 1500 lb. represented working pressures of flanges in elevated temperature service. API assumed the ambient temperature working pressure for the 300 lb. and 400 lb. CLASS and assumed ambient temperatures for 2000, 3000, and 5000 psi flanges also. ANSI has since dropped the previous ASA term "lb." and now refers to flanges by "CLASS". Today, API Spec 6A specifies standard service temperatures of -75° F to 250° F. Current API Spec 6A flanges classed as 6B by API (easily identified by the fact that they have ring grooves that accept R or RX ring gaskets) have identical dimensions with ANSI B16.5 flanges. Caution: A connection between mating ANSI and API flanges requires a rating of the connection no higher than the ANSI pressure rating. In 1945 API introduced flanges rated at 7500 psi, and by 1949 these flanges were given new material specifications, a 10,000 psi working pressure, and the classification "SERIES" 2900. Then API included them with the earlier flanges under the new specification designation STANDARD 6B. By 1957 API adopted new flanges from the Association of Well Head Equipment Manufacturers (AWHEM, See Related Links) designs to replace the "SERIES" 2900. These new 10,000 psi flanges were specified in API STANDARD 6BX. In 1961, STANDARD 6B and STANDARD 6BX were combined into STANDARD 6A, now designated Spec 6A. API included 15,000 psi and 20,000 psi flanges in more recent editions of API Spec 6A. API classes all flanges that accept BX ring gaskets as 6BX flanges. API 6BX open face flanges must have raised faces, while API 6BX Studded Face flanges may have their raised faces omitted. Most manufacturers make API 6BX studded face flanges without raised faces. API Spec 6AB, introduced in 1983, specified 30,000 psi flanged equipment. Spec 6AB has failed to achieve reaffirmation by API so it has the current status of "withdrawn". API Spec 17D, 1st edition, appeared in 1992. This specification introduced 5,000 psi working pressure Type 17SS and 17SV swivel flanges and 10,000 psi swivel flanges that connect to API Spec 6BX flanges of the same working pressure. These flanges for subsea applications have dimensions to accept BX ring gaskets. Spec 17D requires all flanges used for subsea applications to have ring grooves manufactured from, or inlayed with, corrosion resistant alloy. This specification also introduced SBX and SRX ring gaskets designed to allow reliable make-up of flanges underwater. For more information specific to API Spec 17D connectors, see About API 17D SS and SV Swivel Flanges on this Web Site. Low pressure Drilling Diverter Systems use MSS SP-44 flanges for 30" 500 psi and 30" 1,000 psi service. Piping Class Ratings based on ASME B16.5 and corresponding PN (Pression Nominal*): Flange Class 150 300 400 600 900 1500 2500 Flange Pressure Nominal, PN 20 50 68 100 150 250 420 * Pression Nominal is the French equivalent of Pressure Nominal Pression Nominal is the rating designator followed by a designation number indicating the approximate pressure rating in bars.
Hydrostatic test pressure for flanged fittings in some common piping materials are indicated in the table below:
Completed two design projects which being delayed for 4 days. REvised and resubmit.
Others 2 more potential jobs still waiting and one for B31.3 design with Skid. Long time friends asking for pricing.... Hope get it to gain more experience. One, still under client review. One is questionable inquiry received since nobody replied if they want to pursue |
Nasrul
14+ years in designing and drafting experience. Archives
January 2014
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